Nitrogen rejection and liquifier system for liquified natural gas production

ABSTRACT

A method for recovering liquefied natural gas from a gas mixture containing natural gas and impurities by subjecting the natural gas to a series of steps beginning with feeding a natural gas stream containing impurities to a nitrogen rejection unit; feeding the purified natural gas stream to a liquefier heat exchanger; expanding the liquefied natural gas and feeding the expanded liquefied natural gas to a flash vessel; flashing the liquid natural gas and separating the liquefied natural gas from the flash gas; and feeding the liquefied natural gas to storage and the flash gas to the nitrogen rejection unit.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority from U.S. provisional patentapplication Ser. No. 61/317,466, filed Mar. 25, 2010.

BACKGROUND OF THE INVENTION

The invention relates to the integration of a liquefied natural gas(LNG) liquefier system with a nitrogen rejection unit (NRU) so as tominimize the capital and operating costs while maintaining liquefiednatural gas product purity requirements.

Renewable methane can be recovered from a number of sources, such asanaerobic digestion of municipal or industrial waste streams, thedegradation of biomass in landfills, the gasification of waste andbiomass streams, amongst others. In many instances, this renewablemethane require purification before it can be used and/or sold intohigher valued markets, such as injection into the pipeline grid, as afeedstock for liquefied natural gas, as a vehicle fuel, or as afeedstock for the production of hydrogen. Further, the energy that isrequired to purify the renewable methane is significant.

The cleanup of biogas/landfill gas is both capital and power intensivebecause it contains a large number of trace and bulk contaminants infairly large concentrations. Various methods are employed to removethese including chilling, cryogenic methods and various adsorption andscrubbing processes. However, these processes can be expensive in bothcapital and operating costs and it is important to minimize these coststo achieve an economically viable process.

A typical process for the purification of the methane frombiogas/landfill gas requires several steps. Sulfur removal is generallyfollowed by drying. The dried gas stream is then treated forcontaminants such a volatile organic compounds by process such asadsorption, CO₂ washing or by cryogenic methods. The stream is thentreated for bulk carbon dioxide removal by a membrane or adsorptionprocess and then is treated for removal of nitrogen. All thesepurification steps are necessary before the biogas/landfill gas can beliquefied and stored in anticipation of being dispensed, or directedtowards other uses, such as pipeline injection, energy production withfuel cells or small-scale hydrogen production. LNG production isparticularly challenging since all condensable contaminants includingcarbon dioxide must be removed to low ppm levels.

The invention will allow for maximizing the methane recovery whilemaintaining high liquefied natural gas product purity. The operator canutilize a smaller nitrogen rejection unit and can optimize powerconsumption. The process of using the nitrogen rejection unit integratedwith the liquefied natural gas liquefier system achieves greater productpurity (>96 mol % methane) and greater than 89% methane recovery thanconventional non-integrated combinations.

By integration of the liquefied natural gas liquefier system with anitrogen rejection unit, the overall system becomes more compact andefficient. This further enables the operator to maximize methanerecovery while maintaining high liquefied natural gas product puritywhile enable a smaller nitrogen rejection unit. The invention furtherallows the operator to optimize power consumption while allowing forsignificantly higher product purity and methane recovery thanconventional or unitegrated NRU and liquefier combinations which arelimited to 96 mol % methane and 80% methane recovery.

SUMMARY OF THE INVENTION

The invention is a method for recovering liquefied natural gascomprising the steps:

Feeding a natural gas stream containing impurities to a nitrogenrejection unit;Feeding the purified natural gas stream to a liquefier heat exchanger;Expanding the liquefied natural gas and feeding the expanded liquefiednatural gas to a flash vessel;Flashing the liquid natural gas and separating the liquefied natural gasfrom the flash gas;Feeding the liquefied natural gas to storage and the flash gas to saidnitrogen rejection unit.

Alternatively, the invention is a method for recovering liquefiednatural gas comprising the steps:

Feeding a natural gas stream containing impurities to a nitrogenrejection unit;Feeding the purified natural gas stream to a liquefier heat exchanger;Expanding the liquefied natural gas and feeding the expanded liquefiednatural gas to a flash vessel;Flashing the liquid natural gas and separating the liquefied natural gasfrom the flash gas;Recovering refrigeration from said flash gas; andFeeding the liquefied natural gas to storage and the flash gas to saidnitrogen rejection unit.

The invention further comprises an apparatus comprising a nitrogenrejection unit, a liquefier heat exchanger and a flash vessel.

The raw feed gas is first compressed and pre-conditioned which entailsthe removal of water, carbon dioxide, non-methane organic compounds(NMOCs) and sulfur compounds by known methods. The partially purifiedgas is fed to the nitrogen rejection unit where much of the nitrogen isrejected. Since product purity and methane recovery are inverselyrelated, nitrogen rejection is limited to maximize the methane recoveryfor the smallest equipment cost. The resulting gas which containssignificantly lower amounts of inerts is fed to the liquefier heatexchanger where it is liquefied at pressure to a subcooled state.Typical pressures range from 30 bar to 6 bar with a tradeoff betweenmixed refrigeration compressor power and compression power for thepurification system. This liquid is expanded through a valve wherebyfurther cooling is effected to about 2 bar (range is 1 to 5 bar).

The two-phase mixture is separated in a flash vessel and the resultingliquid is directed to the storage tanks, while the flash gas which isricher in nitrogen is recycled back to the nitrogen rejection unit. Theflash gas can also be combined with the raw natural gas/biogas at thefront end of the overall process if the nitrogen rejection unit does nothave a recycle compressor. Clearly additional flash gas from the storagetank will be produced. This too is recycled back to the nitrogenrejection unit or to the front end of the cleanup process. The onlymethane that will be lost is the nitrogen rejection unit waste streamwhich is nitrogen-rich but otherwise very pure and can be flared orconverted into power using a gas engine or a fuel cell.

The end flash from the flash vessel has an additional advantage in thatthe liquid outlet of a flash is at equilibrium which implies that itwill produce some more gas inside the line between the end flash andstorage tank because of product line pressure drop. Therefore, it isbest practice that the flash pressure be lower than the storagepressure. To maximize liquefied natural gas production and minimizeproduct flash losses, the first flash within the flash vessel iseffected at a pressure lower than the storage tank pressure, whence, theliquid coming down from the end-flash tank will be sub-cooled at storagepressure. A cryogenic pump can be utilized to overcome this concern, butinvolves additional cost, maintenance and potential reliability issues.Therefore it is advisable to have horizontal storage tanks, and a coldbox layout so that the liquid level inside the end flash will be higherby a few hundreds of mbar of equivalent liquefied natural gas head thatthe top of the storage and to use that additional head to pressurizeFIG. 2 c.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a typical mixed refrigerant liquefied natural gas liquefier.

FIG. 2 a is an integrated mixed refrigerant liquefied natural gasliquefier.

FIG. 2 b depicts a different embodiment of an integrated mixedrefrigerant liquefied natural gas liquefier.

FIG. 2 c depicts another embodiment of an integrated mixed refrigerantliquefied natural gas liquefier.

FIG. 3 shows methane recovery versus nitrogen rejection unit productmethane content.

FIG. 4 shows a liquefier embodied in the invention.

FIG. 5 a shows a liquefier having a lower cost to operate.

FIG. 5 b shows a different embodiment of a lower cost to operateliquefier.

DETAILED DESCRIPTION OF THE INVENTION

Landfill gas is purified and all the water, sulfur compounds, NMOCs andcarbon dioxide are removed in a pre-purification process. The purifiedgas contains methane, nitrogen and oxygen and has the followingcomposition:

TABLE 1 NRU Feed Gas Composition Species Mole Fraction Carbon Dioxide0.0100 Nitrogen 0.2160 Methane 0.7720 Oxygen 0.0020

The gas is further purified in an adsorption system so that the carbondioxide level is reduced below 50 ppmv and a large portion of thenitrogen is removed. Oxygen usually does not adsorb appreciably andabout 50% of the oxygen is removed in each case. FIG. 1 illustrates atypical MR liquefier stream without process integration. In this caseboth storage tank losses and nitrogen rejection unit waste streams arenot recovered.

Turning to the figures, FIG. 1, represents a base case mixed refrigerantliquefied natural gas liquefier. Purified natural gas is fed throughline 1 through main heat exchanger A where it will be warmed and fedthrough valve V1 and line 2 as liquefied natural gas to a storagecontainer, not shown.

A cold water stream (CWS) is fed through line 11 to heat exchanger E aswell as through valve V6 and line 13 to line 12 as cold water return(CWR). The cold mixed refrigerant is fed through line 9 to knockout drumB where it will proceed through line 7A to refrigerant pump C andthrough open valve V4 to contact line 3 in heat exchanger A. When valveV4 is closed and valve V5 is open the mixed refrigerant will re-enterknock out drum B through line 7. The overhead from knockout drum B willtravel through line 3 to heat exchanger A and enter valve V2 to columnunit D where it will exit unit D through overhead line 4 as well asthrough the bottom of unit D through line 5A. This will exit heatexchanger A through line 5 and connect to inlet separator G where thebottoms will travel through line 8 and transfer pump H to line 6 whichwill enter the knockout drum B. The refrigerant will leave the inletseparator G through line 8A and connect to mixed refrigerant column unitF where the mixed refrigerant will travel through line 10 back to heatexchanger E.

In FIG. 2 a, an integrated mixed refrigerant liquefied natural gasliquefier system is shown per the operation of the invention. Nitrogencontaining biogas or other source of natural gas such as landfill gasfeed is fed through line 23 to nitrogen rejection unit R which istypically a vacuum swing adsorption (VSA) system. Waste gas is fedthrough line 25 to blower S and released into the atmosphere.Depressurization gas is released through line 25A into line 22 where itwill travel through recycle compressor Q and reenter the nitrogencontaining landfill or biogas feed line 23.

The nitrogen recovery unit product/liquefier feed natural gas is fedthrough line 24 into heat exchanger I where it will pass through valveV12 and enter flash tank J. The now liquefied natural gas will exitthrough valve V11 and line 25 to line 26 where it will enter storagetank K and can be accessed through line 21 and valve V10 for later use.Vent gas from the storage tank K will exit through line 20 where it willjoin line 22 and be fed back through the recycle compressor Q to thenitrogen containing biogas feed line 23.

Heat exchanger T is fed cold water through line 35A to provide a coolingmedium which will also feed to the cold water return line 35 throughvalve V16. Line 24A directs warm water leaving heat exchanger T. Thecold refrigerant is fed through line 36 to knock out drum P which feedsthe cold refrigerant to the heat exchanger I through line 28 and whichpasses through valve V13 to the column unit L where refrigerant from thetop exits through line 31 and through the bottom through 31A which joinsline 31 and passes through heat exchanger I and line 31 will be fed toinlet separator M where refrigerant exits through line 33 and is fed tomixed refrigerant column unit U which feeds mixed refrigerant, nowwarmer to the heat exchanger T through line 24. The bottoms from theinlet separator M is fed through line 32 and transfer pump N back toknock out drum P. The bottoms from the knockout drum P are fed throughline 30 and refrigerant pump O to valve V15 for reentry back into theknockout drum P. BZ designates the cold box boundary.

The refrigerant from the knockout drum P may also enter line 29 and openvalve V14 where it will feed into line 31 and entry into the inletseparator M.

FIG. 2 b is a similar version of the integrated mixed refrigerantliquefied natural gas liquefier system of FIG. 2A with the numberingbeing the same as FIG. 2A. This embodiment has compressor Q on line 23rather than line 22 and no return line 25A from the nitrogen rejectionunit R to line 22. Also, line 30A connects with valve V15A to heatexchanger I such that refrigerant from knock out drum P is directed tothe heat exchanger I.

FIG. 2 c is another embodiment of the invention showing an integratedmixed refrigerant liquefied natural gas liquefier. Natural gas such asthat from landfill gas or biogas from a nitrogen recovery unit, notshown, is fed through line 40 into heat exchanger V. The natural gas isliquefied and its pressure is higher as it exits through line 40Athrough temperature control valve V17. The liquefied natural gas entersend flash unit W where the flashed liquefied natural gas is fed throughline 41 and open pressure control valve V18 and recycled back to heatexchanger V where it will exit and be fed through line 42 to a nitrogenrecovery unit, not shown.

The bottoms from the flash unit W exit through line 43 and open valveV19 where it will enter horizontal cryogenic storage tank Y. Additionalstatic head is maintained between the liquid level in the end flash unitW and the horizontal cryogenic storage tank Y such that it is equivalentto subcooling at storage level and pressure. Line BZ represents the coldbox boundary.

FIG. 3 shows the effect of methane product purity on methane recovery.Methane recovery decreases as the nitrogen recovery unit product methanecontent in mole % increases.

FIG. 4 shows a preferred liquefier embodiment. Natural gas such as thatfound in landfill gas or biogas is fed through line 64 to heat exchangerAA where it will exit as liquefied natural gas through open valve V20and be fed to flash tank AB. The liquefied natural gas from the bottomsof the flash tank AB will exit through line 66 and open valve V22 whereit will be fed to storage, not shown. The gaseous natural gas tops ofthe flash tank will exit through line 65 and re-enter heat exchanger AAwhere it will be fed to a mixed gas nitrogen recovery unit, not shown.

Cold water is fed through line 60 into heat exchanger AI to provide acooling medium and also fed through line 61 and open valve V25 to thecold water return line 62. Refrigerant will exit through line 64 and befed through to a knockout drum AD where refrigerant is fed through line51 and refrigerant pump AE through open valve V24 to line 52 passingthrough heat exchanger AA. When valve V24 is closed and valve V24A isopen, the refrigerant is fed through line 55 back to knockout drum AD.Refrigerant is also fed through line 56 from the top of the knockoutdrum AD to line 52 passing through heat exchanger AA. Line 52 willdeliver the refrigerant through open valve V21 to a column unit AC wherethe bottoms from said unit are fed through line 53 to rejoin with thetops which exit unit AC through line 54. Line 54 passes through heatexchanger AA where it will be fed to inlet separator AF.

The refrigerant in line 54 is occasionally supplemented from theknockout drum AD through open valve V23 and line 57 which connects withthe tops from the knockout drum AD through line 56. Line 54 will enterthe inlet separator AF where its bottoms are transferred through line58A and transfer pump AG to line 50 which returns to the knockout drumAD. The tops from the inlet separator AF exit through line 58 and entermixed refrigerant column unit AH where mixed refrigerant will enter theheat exchanger AI for cooling and reentry into the knockout drum AD forentry into heat exchanger AA.

FIG. 5 a shows a lower cost embodiment liquefier. Natural gas such asthat found in landfill gas or biogas is fed through line 79 and openvalve V30 where it will enter flash tank BA. Liquefied natural gas exitsthrough line 77 and open valve V33 to storage, not shown. Natural gaswill exit the flash tank BA through line 78 where it will pass througheconomizer BC and exit to a nitrogen recovery unit, not shown. Valve V32can be opened and excess nitrogen can be recovered through line 78A,unit TIC back into flash tank BA.

Part of the natural gas feed from line 78 is fed through open valve V31to line 76 which passes through heat exchanger BD and open valve V34back to the flash tank BA as liquefied natural gas.

Cold water is fed through line 83 to heat exchanger BJ and through line85 and open valve V39 to cold water return line 84. Refrigerant willexit through line 85A and be fed to knockout drum BH where it will exitthrough the bottom of the knockout drum through open valve V36 andrefrigerant pump BI to be fed to line 74 passing through heat exchangerBD. Valve V36 can be closed and valve V38 open such that refrigerantwill pass through line 75 back to knockout drum BR

The tops from the knockout drum BH will be fed through line 70 to line74 passing through heat exchanger BD. The refrigerant will pass throughopen valve V35 and be fed to column unit BE where the bottoms from theunit exit through line 71 and join with the tops from the unit BE line72 which passes refrigerant through heat exchanger BD. This refrigerantwill enter inlet separator BG through line 72 where the bottoms from theinlet separator BG are fed through line 80 and transfer pump BF back tothe knockout drum BH.

The tops from the inlet separator will exit through line 81 to mixedrefrigerant unit BK. The mixed refrigerant from unit BK is fed back toheat exchanger BJ as a warm fluid through line 82 where it will becooled down and ultimately fed back into heat exchanger BD after passingthrough knockout drum BH. Line BZ designates the cold box boundary.

FIG. 5 b is virtually identical to FIG. 5 a designating a lower costliquefier embodiment. In this embodiment, the numbering is the same andthere is no return embodiment on top of the flash tank BA, thus line78A, valve V32 and TIC control mechanism are not present. In FIG. 5 b,the cold box boundary BZ is also broader and covers the flash tank BAwhich is not seen in FIG. 5 a.

Typical nitrogen rejection performance is shown in FIG. 3 for a vacuumswing adsorption (VSA) nitrogen rejection unit. The invention is shownin FIG. 2 a. The nitrogen rejection amount was varied while ensuringthat the final LNG product contained 98%+methane. Three cases wereconsidered for illustrative purposes where the NRU product/liquefierfeed gas contained 90.6, 98.2 and 98% methane (C1). The relativeequipment size, which determines capital cost and the power werecalculated and compared. The results are as indicated in Tables 2 and 3below. In Table 2, both the pre-cleanup system, which is used to removeall contaminants other than nitrogen and oxygen, and the four bed VSAsystem are compared in terms of size which is directly proportional tothe kg-moles/hr of NRU feed to be processed or the nitrogen to berejected. Case 3 clearly shows significant benefits when a less pure NRUproduct is fed to the liquefier with a pre-cleanup system that is 17%smaller and a NRU that is 23% smaller than the first case.

TABLE 2 Effect of Liquefier Feed Composition on Overall Methane Recoveryand Equipment Size C1 in Liquefier Pre-Cleanup NRU Wobbe Index Feed (mol%) Relative Size Relative Size (MJ/m³) Case 1 98.0 1.17 1.23 50.37 Case2 96.2 1.06 1.10 50.11 Case 3 90.6 1.00 1.00 49.35

In addition, the relative power for all 3 cases is compared in Table 3which shows that the extra power needed for liquefaction and recyclewith higher inerts (case 1) is compensated by the vacuum pump powerneeded for higher NRU purity (case 3). Hence, there is no appreciablenet power penalty.

TABLE 3 Effect of Liquefier Feed Composition on Net Power C1 inLiquefier Feed Relative Power (mol %) (%) Case 1 98.0 100.5 Case 2 96.299.6 Case 3 90.6 100.0

Other embodiments of the invention are illustrated in FIGS. 5 a and 5 b,both of which are lower capital cost options and do not require aseparate pass in the main heat exchanger, or a larger coldbox.Nevertheless, both embodiments do not allow for full cold recovery andare less efficient. Additionally, if all the purified natural gas fromthe NRU is fed to the economizer, a very large temperature gradient willresult at the cold end of this exchanger. Therefore, it is desired thatonly a portion of the NRU product is fed to the economizer so that itcan be liquefied, or cooled close to the liquefaction temperature. Theportion of the NRU product gas cooled in the economizer can be sent toflash tank labeled BA in FIGS. 5 a and 5 b as sub-cooled liquid or tothe main heat exchanger.

While this invention has been described with respect to particularembodiments thereof, it is apparent that numerous other forms andmodifications of the invention will be obvious to those skilled in theart. The appended claims in this invention generally should be construedto cover all such obvious forms and modifications which are within thetrue spirit and scope of the invention.

Having thus described the invention, what we claim is:
 1. A method forrecovering liquefied natural gas comprising the steps: feeding a naturalgas stream containing impurities to a nitrogen rejection unit; feedingthe purified natural gas stream to a liquefier heat exchanger; expandingthe liquefied natural gas and feeding the expanded liquefied natural gasto a flash vessel; flashing the liquid natural gas and separating theliquefied natural gas from the flash gas; and feeding the liquefiednatural gas to storage and the flash gas to said nitrogen rejectionunit.
 2. The method as claimed in claim 1 wherein said impurities areselected from the group consisting of water, carbon dioxide, non-methaneorganic compounds and sulfur compounds.
 3. The method as claimed inclaim 1 wherein nitrogen is recovered from said nitrogen rejection unit.4. The method as claimed in claim 1 wherein the pressure in saidliquefier heat exchanger range from 6 to 30 bar.
 5. The method asclaimed in claim 1 wherein said liquefied natural gas is expanded to apressure of 1 to 5 bar.
 6. The method as claimed in claim 1 wherein saidflash gas is richer in nitrogen than natural gas.
 7. The method asclaimed in claim 1 wherein said natural gas stream is selected from thegroup consisting of landfill gas and biogas.
 8. The method as claimed inclaim 1 wherein said flash gas is recycled to said natural gas feed. 9.The method as claimed in claim 1 wherein flash pressure is lower thanstorage pressure.
 10. The method as claimed in claim 1 wherein saidnitrogen rejection unit is a vacuum swing adsorption unit.
 11. Themethod as claimed in claim 1 wherein said recovered natural gas is fedto a storage unit.
 12. The method as claimed in claim 1 wherein saidstorage unit is situated horizontally.
 13. A method for recoveringliquefied natural gas comprising the steps: feeding a natural gas streamcontaining impurities to a nitrogen rejection unit; feeding the purifiednatural gas stream to a liquefier heat exchanger; expanding theliquefied natural gas and feeding the expanded liquefied natural gas toa flash vessel; flashing the liquid natural gas and separating theliquefied natural gas from the flash gas; recovering refrigeration fromsaid flash gas; and feeding the liquefied natural gas to storage and theflash gas to said nitrogen rejection unit.
 14. The method as claimed inclaim 13 wherein said impurities are selected from the group consistingof water, carbon dioxide, non-methane organic compounds and sulfurcompounds.
 15. The method as claimed in claim 13 wherein nitrogen isrecovered from said nitrogen rejection unit.
 16. The method as claimedin claim 13 wherein the pressure in said liquefier heat exchanger rangefrom 6 to 30 bar.
 17. The method as claimed in claim 13 wherein saidliquefied natural gas is expanded to a pressure of 1 to 5 bar.
 18. Themethod as claimed in claim 13 wherein said flash gas is richer innitrogen than natural gas.
 19. The method as claimed in claim 13 whereinsaid natural gas stream is selected from the group consisting oflandfill gas and biogas.
 20. The method as claimed in claim 13 whereinsaid flash gas is recycled to said natural gas feed.
 21. The method asclaimed in claim 13 wherein flash pressure is lower than storagepressure.
 22. The method as claimed in claim 13 wherein said nitrogenrejection unit is a vacuum swing adsorption unit.
 23. The method asclaimed in claim 13 wherein said recovered natural gas is fed to astorage unit.
 24. The method as claimed in claim 13 wherein said storageunit is situated horizontally.
 25. The method as claimed in claim 13wherein said recovered refrigeration provides cooling to a heatexchanger.
 26. The method as claimed in claim 13 wherein said heatexchanger is in thermal contact with the liquefier feed.
 27. Anapparatus comprising a nitrogen rejection unit, a liquefier heatexchanger and a flash vessel.
 28. The apparatus as claimed in claim 27wherein said nitrogen rejection unit is a vacuum swing adsorption unit.29. The apparatus as claimed in claim 27 wherein said liquefier heatexchanger is in thermal communication with said flash vessel.
 30. Theapparatus as claimed in claim 27 wherein said nitrogen rejection unit isin thermal communication with said liquefier heat exchanger.
 31. Theapparatus as acclaimed in claim 27 wherein said flash vessel is in fluidcommunication with a storage tank.
 32. The apparatus as claimed in claim27 further comprising a second heat exchanger.